1. Field of the Invention
The present invention provides an improved method for design and control of drilling operations.
2. Background of the Related Art
Wells are generally drilled to recover natural deposits of hydrocarbons and other desirable, naturally occurring materials trapped in geological formations in the earth""s crust. A slender well is drilled into the ground and directed to the targeted geological location from a drilling rig at the surface. In conventional xe2x80x9crotary drillingxe2x80x9d operations, the drilling rig rotates a drillstring comprised of tubular joints of drill pipe connected together to turn a bottom hole assembly (BHA) and a drill bit that is attached to the lower end of the drillstring. During drilling operations, a drilling fluid, commonly referred to as drilling mud, is pumped and circulated down the interior of the drillpipe, through the BHA and the bit, and back to the surface in the annulus. It is also well known in the art to utilize a downhole mud-driven motor, located just above the drill bit, that converts hydraulic energy stored in the pressurized drilling mud into mechanical power to rotate the drill bit.
To isolate geologic formations from the wellbore and to prevent collapse of the well, the well is generally cased with tubular pipe joints connected together with threaded connections to form a casing string. The casing string is generally installed in stages, a section of casing being installed in each stage. A section of casing generally comprises many connected joints of casing, all sections linked together to form the casing string.
Each section of casing is installed and cemented into place in the wellbore by circulating cement into the annular area defined by the outer surface of the section of casing and the inner bore wall of the wellbore. Casing sections are generally installed in successively decreasing diameters so that subsequent smaller diameter sections of casing can be installed and cemented in deeper portions of the well as drilling progresses. Installation of a section of casing requires the driller to remove the drillstring, including the BHA and the bit, from the well. The drillstring is removed from the well joint by joint in a time-consuming operation. Later, after the section of casing is cemented into place and the cement has sufficiently cured, the drillstring is again tripped into the well joint by joint before drilling operations can resume.
There is a strong cost-based incentive to maximize the length of each section of casing and to minimize the frequency of drilling rig downtime for tripping drillpipe out of and into the well. If the number of casing stages can be safely reduced using more accurate methods of assessing downhole conditions and estimating downhole pressures, then the well can be drilled faster and with considerably lower cost for the drilling rig and related support.
The pressure of porous and permeable geologic formation(s) is generally balanced by hydrostatic pressure applied by the column of drilling mud plus the pressure applied to or held on the well at the surface. Pressure may be applied in the drillstring by mud pumps to cause mud to circulate down the interior of the drillstring, through the bit and back up to the surface through the annulus. Drilling mud is designed to suspend and carry back to the surface small bits of rock called cuttings that are produced by the drilling process. Pressure may be held on the casing when the annulus is isolated from the atmosphere by closure of the blow-out preventers (BOPs) at the surface.
The driller generally controls hydrostatic pressures in the well by use of weighting agents added to the drilling mud to increase density. The driller generally controls the pressure on the well at the surface by activation or deactivation of the mud circulating pumps and by using the BOPs to isolate the annulus from the atmosphere. However, the driller cannot always control pressures occurring downhole at the formation because other factors affect the pressure applied to the formation at any given moment. These other factors include:
(a) pipe movement in the wellbore (rotation or reciprocation),
(b) temperatures and temperature gradients,
(c) pressure gradients and propagation rates of pressure fronts,
(d) viscosity and thixotropic properties of the drilling mud
(e) loading of cuttings from drilling, and
(f) fluid flows into and out of the wellbore.
Many types of geologic formations commonly encountered in drilling will fracture and fail if subjected to excessive pressure applied in the wellbore. Many types of fluid-bearing geologic formations are porous or permeable, and may either flow fluid into the wellbore or accept fluids from the wellbore. It is generally desirable to keep the pressure in the well adjacent to such formations above the pore pressure of porous formations and below the formation fracture pressure of exposed formations. This xe2x80x9cwindow of safetyxe2x80x9d defined by the range of pressure between the pore pressure and the formation fracture pressure must be determined by the driller in order to design a safe and effective drilling plan and to make good decisions throughout the drilling process. Accurate determination of this window of safety directly effects the economic success of the drilling venture.
If the downhole pressure exceeds the formation fracture pressure, the region of the formation exposed to the downhole pressure will begin to physically break down and drilling mud will flow from the wellbore into the fractured formation at a rate determined by the extent of the fracture and the pressure differential. The resulting loss of overall height of the hydrostatic column of drilling mud can quickly result in inadequate well pressure at the formation. When this condition occurs, formation fluids, including gases, may enter the well from other formations in fluid communication with the well. This occurrence is commonly referred to as a kick. Once introduced into the wellbore, the gas migrates upwardly through the drilling mud towards the surface. The upwardly migrating gas expands as it encounters lower pressures, often forcing drilling mud to flow out of the well either at the surface or into formations in fluid communication with the well. This is a dangerous well control situation that must be avoided or responded to quickly. It is important that the driller avoids inadvertent fracturing of formations.
A well control situation can also develop if the pressure at the formation face falls below the pore pressure of fluids that may reside in porous formations. This well condition is commonly referred to as underbalanced. When the well is underbalanced, fluids from porous geologic formations that are in fluid communication with the well will flow into the well, displacing drilling mud upwardly towards the surface. As with the formation fracture, gas introduced through underbalanced conditions will also migrate to the surface and expand.
The xe2x80x9cwindow of safetyxe2x80x9d or range of allowable downhole pressures may be defined by formation pore pressures (minimum) and the formation fracture pressure (maximum). Accurate determination of this window of safety has become increasingly important as technology has progressed and wells are drilled:
(a) in deep water locations where water temperature and depth affect changes in well design and dynamics,
(b) as higher formation pore pressures, or formations with lower fracture pressures are encountered,
(c) in extended reach wells drilled using directional drilling techniques,
(d) in wells with extremely slender boreholes with increased friction losses for required circulating mud pressures, and
(e) in extreme conditions of pressure and temperature, referred to as HPHT wells (high-pressure and high-temperature wells).
The driller can determine the pore pressure of fluid-bearing formations in a number of ways well known in the art. The driller can perform a leak-off test/formation integrity test (LOT/FIT) to test cement placed behind casing (LOT) and to test any exposed formation(s) to determine the pressure at which the formation will fracture or mud will be lost into the formation (FIT). A LOT/FIT is generally performed by first closing the BOPs at the surface to isolate the well from the atmosphere, and then pumping drilling mud into the wellbore from the surface at a slow, constant volumetric flowrate to increase the pressure in the well. The pumping continues, either continuously or in volumetric increments with intermittent static periods, until a predetermined test pressure is reached or until drilling fluid loss from the well is detected. If the cement placed behind the casing is sound, drilling fluid loss usually occurs when an exposed formation begins to fracture or accept fluid from the well.
The formation fracture pressure is calculated or determined using the LOT/FIT test results. Initially, a plot of surface (injection) pressure versus cumulative volume pumped will define an upwardly sloping, straight line as shown in FIG. 1. When the mud pressure at the downhole, exposed formation exceeds its formation fracture strength, the formation starts taking fluid from the wellbore and the injection pressure will either decline or increase non-linearly with-further increases in the volume pumped. That is, once the formation fracture pressure is reached, additional incremental increases in injection pressure cause greater volumes of mud displacement into the formation. This relationship is shown on FIG. 1, and the formation fracture pressure at point 10 in this example corresponds to the magnitude of the injection pressure where non-linear deviation occurs. The formation fracture pressure is often calculated as the surface or injection pressure at which the non-linear deviation occurs plus the hydrostatic pressure as calculated by the product of the density of the drilling mud times the vertical height of the mud column above the formation.
One problem with this method is that the formation fracture pressure calculated fails to take into account the effects of several factors that may affect the actual pressure in the well at the formation. For example, the formation fracture determined by the graphical analysis described above does not necessarily correspond to the exact time at which fluid starts to flow into the fracturing formation. Also, if the openhole section (below the cemented sections of the casing) passes through a permeable zone, fluid could be leaking from the well at a constant rate during the LOT/FIT. This scenario would still result in a linear pressure-volume plot during the LOT/FIT. Other factors that theoretically affect the pressure in the wellbore adjacent to the formation include, but are not limited to: 1) mud compressibility, 2) elastic and inelastic expansion of the wellbore and casing, 3) elastic expansion and elongation of the drillstring, 4) non-uniform dispersal of cuttings and mud weighting agents in the drilling mud, 5) non-uniform density of the mud throughout the mud column; 6) pressure propagation speeds through the mud column, 7) gel properties of the mud system, and 8) frictional pressure losses due to wellbore geometry and mud rheology.
Downhole instruments have been developed to provide accurate measurements of downhole pressures. Some of these instruments have a hard-line or cabled connection for transmitting data back to the surface. These instruments are usually slim pieces of equipment that are run into the well inside the drillstring. In these types of systems, the amount of real-time data that can be transmitted to and used by the driller at the surface is virtually unlimited. However, most hard-line or cabled instruments cannot be used without severely impairing drilling operations. The cable and the instrument must be withdrawn from the well during drilling operations when the data is needed most. Cabled instruments can also be run into the well after the drillstring is removed from the wellbore, but again this is impractical for efficient drilling operations and does not provide xe2x80x9creal timexe2x80x9d (or near xe2x80x9creal timexe2x80x9d) information while drilling.
A mud pulse telemetry communication system for communicating data from the BHA to the surface has been developed and has gained widespread acceptance in the industry. Mud pulse telemetry systems have no cables or wires for carrying data to the surface, but instead use a series of pressure pulses that are carried to the surface through flowing, pressurized drilling fluid. One such system is described in U.S. Pat. No. 4,120,097. The limitation with mud pulse telemetry systems is that data transmission capacity, or information transmission rate, is extremely limited. Also, data gathered and/or stored downhole in bottom-hole assemblies (BHA) can only be transmitted to the surface using mud pulse telemetry during a xe2x80x9cpumps-onxe2x80x9d condition, which is defined as when the mud circulation rate is above the mud pulse telemetry operating threshold. Accordingly, during xe2x80x9cpumps-offxe2x80x9d operations, which are defined as when mud circulating pumps are inactive or during low pump rate operations such as LOT/FIT and during pipe joint connections, no downhole data can be transmitted to the surface using mud pulse telemetry systems. The data gathered and stored in the BHA during these pumps-off operations can only be transmitted to the surface after the circulating pumps have been turned back on, and even then, the data transmission is very slow.
Attempts have been made to formulate a predictor equation for use in estimating downhole conditions, including pressure, based on surface measurements. Rasmus discloses in his U.S. Pat. No. 5,654,503 a method for obtaining improved measurement of drilling conditions. Rasmus attempts to overcome the limited information transmission rate of mud pulse telemetry systems by formulating a predictor equation relating a surface condition to a related downhole condition at a given time. The Rasmus predictor equation is formulated by using a downhole instrument in the BHA to make numerous downhole measurements over a given time period. Rasmus then averages these measurements in a downhole CPU, and sends the averaged downhole Addition measurement to the surface for comparison with actual related surface condition measurements.
The Rasmus method may be used to approximate downhole pressure based on surface pressure. However, the Rasmus method fails to compensate for influences from pipe movement (rotation or reciprocation), temperature gradients, pressure gradients and propagation, viscosity and thixotropic properties of the drilling mud, and fluid flow into and out of the wellbore, or combinations of these influences, that can cause deviations and transients in the downhole measurements. By taking an average of numerous measurements of the downhole pressure, the Rasmus method irreversibly mixes the influence of these transients into the averaged downhole value, which is then communicated to the surface for comparison to an accurate surface pressure measurement. Furthermore, the Rasmus method uses a cumbersome sequencing technique to time-shift and re-align downhole data averages with selected surface measurements. In other words, it correlates an average taken over a given period of time, for example, 30 seconds, with a single surface measurement taken sometime during or prior to that 30 seconds. Substantial inaccuracies are introduced in the averaging step, and again in the time sequencing step, and these result in a poor approximation of coefficients used in the Rasmus predictor equation to estimate downhole pressures and to diagnose well conditions.
What is needed is a method of estimating downhole pressure that allows the driller to use a limited amount of strategically selected pressure data taken downhole, along with readily available surface pressure data, to accurately estimate formation fracture pressure and other critical downhole pressures, and to diagnose well conditions and well behavior. What is needed is a method of selecting and communicating only those specific downhole measurements that provide the most beneficial information for quickly and accurately correlating to related surface pressure measurements, and then estimating downhole pressures, diagnosing exhibited well behavior and responding to developing well conditions. It would be desirable if this method would enable the driller to better estimate formation fracture pressures by determining and updating an equation that, through the use of parameters, takes into account the transients introduced by factors known to affect downhole pressures. It would also be desirable if this method would enable the driller to avoid the time-consuming step of circulating mud in the well for a period of time prior to the LOT/FIT in order to condition the mud and promote uniform density through mixing.
The present invention provides a method of determining downhole pressures occurring during a pumps-off condition, such as during a leak-off test or formation integrity test (LOT/FIT). The method comprises measuring the wellbore pressure at the surface during the pumps-off condition. The pressure in the well is then increased as part of the condition, for example the LOT/FIT. Maximum and minimum pressures occurring downhole during the pumps-off condition are measured by the BHA and, immediately following the resumption of pumps-on operation, the maximum and minimum downhole pressure measurements are communicated to the surface. Then, the downhole maximum and minimum pressures are correlated with the maximum and minimum surface pressure measurements to arrive at one or more representative downhole pressures using the correlation.
Optionally, the method may further comprise the steps of measuring additional downhole pressure measurements, recording the times at which each of the additional downhole pressure measurements were made, and communicating the additional downhole pressure measurements and their corresponding xe2x80x9ctime-stampsxe2x80x9d to the surface after the pumps-off condition. The additional downhole measurements communicated to the surface allow further correlation with related surface pressure measurements occurring simultaneously or in a spaced time relationship with each downhole measurement. The preferred application for these methods is a LOT/FIT, wherein the pressure in the well is increased by injection of fluid, such as drilling mud.
The invention also provides a similar method that includes measuring a first downhole pressure and a second downhole pressure during the pumps-off condition along with the times at which each measurement occurs. These first and second downhole pressure measurements, along with their respective time-stamps, are communicated to the surface immediately following the resumption of pumps-on operations. This allows a correlation of the first downhole pressure to the surface pressure occurring simultaneously, or in a spaced time relationship, with the first downhole pressure, and correlation of the second downhole pressure to the surface pressure occurring simultaneously, or in a spaced time relationship, with the second downhole pressure. Using this correlation, it is possible to arrive at one or more representative downhole pressures as a function of the measured surface pressures.